In deep water drilling, it is necessary to discharge certain fluids in order to set two conductor strings into the upper portion of the wellbore. The reason for this is that the driller can not fracture formation and inject the fluids under the circulating pressure without fracturing back to the surface so it is necessary to set 20 inch casing to a depth sufficient that he will not fracture back to the surface, which is the sea floor. In order to do this, he use fluids that are compatible with the environment and that do not contaminate the environment. For example, the optimum drilling fluids may not be employed in this early portion and elements that are objected to, such as diesel oil, lignosulfonate muds, chrome, and the like are not employed in this early drilling. Typically, in the borehole a 30 inch conductor pipe is installed, the borehole is then drilled to the desired depth for 20 inch conductor pipe and the 20 inch conductor pipe is then inserted interiorly of the 30 inch pipe. The 20 inch conductor pipe is cemented in place with returns to the sea floor. The materials are deposited on the sea floor at the wellbore site but none of these materials are considered toxic.
With jackup rigs, after the 20 inch conductor string is cemented in place, it has been practice to fracture into a subterranean formation and then to use one annulus between the 30 inch conductor string and the 133/8 inch casing for injecting wastes therethrough and into the fractured formation.
With the advent of floating rigs, this approach was not available, since there had been no system for reaching the annulus on the subsea stack employed with a floating rig.
In the prior art the most common subsea BOP (blowout preventor) stack on large semis is the 183/4 inch bore, 10,000 psi (pounds per square inch) working pressure stack. These are used with 183/4 inch 10,000 psi working pressure wellheads. The wellheads are run on the 20 inch conductor pipe and landed in a head attached to the 30 inch conductor pipe that is placed to start the well. The 183/4 10,000 psi wellhead usually permit landing three or four additional strings in the head. The most common of these are the 133/8 OD (outside diameter) surface pipe followed by 95/8 inch OD protection casing, 7 inch OD tieback string and test tubing. Ordinarily, the conventional prior art apparatus includes conventional permanent and temporary guide bases with typical wellhead connectors and cables and other guide means for guiding the equipment to the subsea wellhead apparatus, as well as conduits, sealing stab connections and the like that will form a sealed flowpath when the stabbed connection is made with the apparatus lowered to the subsea wellhead apparatus. The risers, control lines, kill lines and the like are employed in accordance with conventional technology.
Drilling fluids are usually returned to the surface when certain geological information is desired to be obtained from the fluid and when it is to be recirculated.
In many instances of such offshore drilling, it would be exceptionally burdensome to have to accumulate and transport waste fluids by supply boat, so the drilling engineer simply uses compatible rather than toxic material and tolerates whatever drilling inefficiencies he has to.
Accordingly, it can be seen that the prior art has not solved the problem of providing a wellhead apparatus that can, at the option of the operator be employed to dispose of accumulated wastes through special conduit connectors communicating with an annulus that communicates with a fractured subterranean formation.